There are a number of oil production operations where the use of downhole electric submersible pumps (ESPs) is necessary to ensure sufficient lift is created to produce a high volume of oil from the well. ESPs are multistage centrifugal pumps having anywhere from ten to hundreds of stages. Each stage of an electric submersible pump includes an impeller and a diffuser. The impeller transfers the shaft's mechanical energy into kinetic energy in the fluid. The diffuser then converts the fluid's kinetic energy into the fluid head or pressure necessary to lift the liquid from the wellbore. As with all fluids, ESPs are designed to run efficiently for a given fluid type, density, viscosity, and an expected amount of free gas.
Free gas, associated gas, or gas entrained in liquid is produced from subterranean formations in both oil production and water production. While ESPs are designed to handle small volumes of entrained gas, the efficiency of an ESP decreases rapidly in the presence of gas. The gas, or gas bubbles, builds up on the low-pressure side of the impeller, which in turn reduces the fluid head generated by the pump. Additionally, the volumetric efficiency of the ESP is reduced because the gas is filling the impeller vanes. At certain volumes of free gas, the pump can experience gas lock, during which the ESP will not generate any fluid head.
Methods to combat problems associated with gas in the use of ESPs can be categorized as gas handling and gas separation and avoidance.
In gas handling techniques, the type of impeller vane used in the stages of the ESP takes into account the expedited free gas volume. ESPs are categorized based on their impeller design as radial flow, mixed flow, and axial flow. In radial flow, the geometry of the impeller vane is more likely to trap gas and therefore it is limited to liquids having less than 10% entrained free gas. In mixed flow impeller stages, the fluid progresses along a more complex flow path, allowing mixed flow pumps to handle up to 25% (45% in some cases) free gas. In axial flow pumps, the flow direction is parallel to the shaft of the pump. The axial flow geometry reduces the opportunity to trap gases in the stages and, therefore, axial pumps can typically handle up to 75% free gas.
Gas separation and avoidance techniques involve separating the free gas from the liquid before the liquid enters the ESP. Separation of the gas from the liquid is achieved by gas separators installed before the pump suction, or by the use of gravity in combination with special completion design, such as shrouds. In most operations, the separated gas is then produced to the surface through the annulus between the tubing and the casing. In some operations, the gas is produced at the surface through separate tubing. In some operations the gas can be introduced back into the tubing that contains the liquids downstream of the pump discharge. In order to do this, the gas may need to be pressurized to achieve equalization of the pressure between the liquid discharged by the pump and the separated gas. A jet pump can be installed above the discharge of the ESP, the jet pump pulls in the gas. Jet pumps are complex and can have efficiency and reliability issues. In some cases however, the gas cannot be produced through the annulus due to systems used to separate the annulus from fluids in the wellbore.
Non-associated gas production wells can also see multiphase streams. Wet gas wells can have liquid entrained in the gas. As with liquid wells, artificial lift can be used to maintain gas production where the pressure in the formation is reduced. In such situations, downhole gas compressors (DGC) are used to generate the pressure necessary to lift the gas to the surface. DGCs experience problems similar to ESPs, when the liquid entrained in the gas is greater than 10%.
In addition to ESPs and DGCs, equipment at the surface can be used to generate pressure for producing the fluids from the wellbore. Multiphase Pumps (MPPs) and Wet Gas Compressors (WGCs) can be used on oil and gas fields respectively. MPP technologies are costly and complex, and are prone to reliability issues. Current WGC technology requires separation, compression, and pumping, where each compressor and pump requires a separate motor.